Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes x No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of large accelerated filer, accelerated filer, and smaller reporting company in Rule 12b-2 of the Exchange Act.

Large accelerated filer o

Accelerated filer o

Non-accelerated filer x

Smaller reporting company o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No x

Indicate the number of shares outstanding of each of the issuers classes of common stock, as of the latest practicable date:

In this report, we make statements concerning our expectations, beliefs, plans, objectives, goals, strategies, and future events or performance. These statements are forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934, as amended. Forward-looking statements are not guarantees of future results and conditions, but rather are subject to numerous management assumptions, risks, and uncertainties. Therefore, actual results may differ materially from those expressed or implied by these statements. Although we believe that these forward-looking statements and the underlying assumptions are reasonable, we cannot provide assurance that such statements will prove correct.

Forward-looking statements involve a number of risks and uncertainties. Some risks that could cause actual results to differ materially from those expressed or implied in forward-looking statements include those described in Item 1A of our Annual Report on Form 10-K for the year ended December 31, 2011, as may be amended or supplemented in Part II, Item 1A of our subsequently filed Quarterly Reports on Form 10-Q (including this report), and those identified below:

·

The timing and resolution of rate cases and related negotiations, including recovery of deferred and current costs and the ability to earn a reasonable return on investment, and other regulatory decisions impacting us;

·

Federal and state legislative and regulatory changes relating to the environment, including climate change and other environmental regulations impacting coal-fired generation facilities and renewable energy standards;

·

Other federal and state legislative and regulatory changes, including deregulation and restructuring of the electric and natural gas utility industries, financial reform, health care reform, energy efficiency mandates, reliability standards, pipeline integrity and safety standards, and changes in tax and other laws and regulations to which we and our subsidiary are subject;

·

Costs and effects of litigation and administrative proceedings, settlements, investigations, and claims, including manufactured gas plant site cleanup, third-party intervention in permitting and licensing projects, and compliance with Clean Air Act requirements at generation plants;

·

Changes in credit ratings and interest rates caused by volatility in the financial markets and actions of rating agencies and their impact on our liquidity and financing efforts;

·

The risks associated with changing commodity prices, particularly natural gas and electricity, and the available sources of fuel, natural gas, and purchased power, including their impact on margins, working capital, and liquidity requirements;

·

The timing and outcome of any audits, disputes, and other proceedings related to taxes;

·

The effects, extent, and timing of additional competition or regulation in the markets in which we operate;

Changes in technology, particularly with respect to new, developing, or alternative sources of generation;

·

The effects of political developments, as well as changes in economic conditions and the related impact on customer use, customer growth, and our ability to adequately forecast energy use for customers;

·

Potential business strategies, including acquisitions and construction or disposition of assets or businesses, which cannot be assured to be completed timely or within budgets;

·

The risk of terrorism or cyber security attacks, including the associated costs to protect our assets and respond to such events;

·

The risk of failure to maintain the security of personally identifiable information, including the associated costs to notify affected persons and to mitigate their information security concerns;

·

The effectiveness of risk management strategies, the use of financial and derivative instruments, and the related recovery of these costs from customers in rates;

·

The risk of financial loss, including increases in bad debt expense, associated with the inability of our counterparties, affiliates, and customers to meet their obligations;

·

Unusual weather and other natural phenomena, including related economic, operational, and/or other ancillary effects of any such events;

·

The effect of accounting pronouncements issued periodically by standard-setting bodies; and

·

Other factors discussed elsewhere herein and in other reports we and/or Integrys Energy Group file with the SEC.

Except to the extent required by the federal securities laws, we undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events, or otherwise.

As used in these notes, the term financial statements refers to the condensed consolidated financial statements. This includes the condensed consolidated statements of income, condensed consolidated balance sheets, condensed consolidated statements of capitalization, and condensed consolidated statements of cash flows, unless otherwise noted. In this report, when we refer to us, we, our, or ours, we are referring to WPS.

We prepare our financial statements in conformity with the rules and regulations of the SEC for Quarterly Reports on Form 10-Q and in accordance with GAAP. Accordingly, these financial statements do not include all of the information and footnotes required by GAAP for annual financial statements. These financial statements should be read in conjunction with the consolidated financial statements and footnotes in our Annual Report on Form 10-K for the year ended December 31, 2011.

In managements opinion, these unaudited financial statements include all adjustments necessary for a fair presentation of financial results. All adjustments are normal and recurring, unless otherwise noted. All intercompany transactions have been eliminated in consolidation. Financial results for an interim period may not give a true indication of results for the year.

Reclassification

We adjusted changes in working capital on the statements of cash flows by reclassifying $6.5 million related to materials and supplies at September 30, 2011, from the change in other current assets line item to the change in inventories line item to be consistent with the current period presentation. This reclassification had no impact on total cash flows from operating activities.

NOTE 2CASH AND CASH EQUIVALENTS

Short-term investments with an original maturity of three months or less are reported as cash equivalents.

The following is a supplemental disclosure to our statements of cash flows:

Nine Months Ended September 30

(Millions)

2012

2011

Cash paid for interest

$

20.8

$

29.8

Cash (received) paid for income taxes

(14.2

)

31.8

Construction costs funded through accounts payable totaled $15.8 million at September 30, 2012, and $7.6 million at September 30, 2011. These costs were treated as noncash investing activities.

NOTE 3RISK MANAGEMENT ACTIVITIES

We use derivative instruments to manage commodity costs. None of these derivatives are designated as hedges for accounting purposes. The derivatives include physical commodity contracts and NYMEX futures and options used by both the electric and natural gas utility segments to manage the risks associated with the market price volatility of natural gas costs and the costs of gasoline and diesel fuel used by our utility vehicles. The electric utility segment also uses financial transmission rights (FTRs) to manage electric transmission congestion costs and NYMEX oil futures and options to reduce price risk related to coal transportation.

The tables below show our assets and liabilities from risk management activities:

Balance Sheet

September 30, 2012

(Millions)

Presentation *

Assets

Liabilities

Natural gas contracts

Other Current

$

1.1

$

0.2

Natural gas contracts

Other Long-term

0.1



FTRs

Other Current

1.9

0.2

Petroleum product contracts

Other Current

0.2



Coal contract

Other Current



5.0

Coal contract

Other Long-term



4.3

Total commodity contracts

Other Current

$

3.2

$

5.4

Total commodity contracts

Other Long-term

$

0.1

$

4.3

*All derivatives are recognized on the balance sheet at their fair value unless they qualify for the normal purchases and sales exception. We continually assess our contracts designated as normal and will discontinue the treatment of these contracts as normal if the required criteria are no longer met. We classify assets and liabilities from risk management activities as current or long-term based upon the maturities of the underlying contracts.

Balance Sheet

December 31, 2011

(Millions)

Presentation *

Assets

Liabilities

Natural gas contracts

Other Current

$

0.1

$

2.5

FTRs

Other Current

1.3

0.1

Petroleum product contracts

Other Current

0.1



Coal contract

Other Current



2.5

Coal contract

Other Long-term



4.4

Total commodity contracts

Other Current

$

1.5

$

5.1

Total commodity contracts

Other Long-term

$



$

4.4

*All derivatives are recognized on the balance sheet at their fair value unless they qualify for the normal purchases and sales exception. We continually assess our contracts designated as normal and will discontinue the treatment of these contracts as normal if the required criteria are no longer met. We classify assets and liabilities from risk management activities as current or long-term based upon the maturities of the underlying contracts.

The following table shows the unrealized gains (losses) recorded related to derivatives:

Three Months Ended September 30

Nine Months Ended September 30

(Millions)

Financial Statement Presentation

2012

2011

2012

2011

Natural gas contracts

Balance Sheet  Regulatory assets (current)

$

0.3

$

(1.7

)

$

2.8

$

0.7

Natural gas contracts

Balance Sheet  Regulatory liabilities (current)

0.3

(0.1

)

0.6

(0.2

)

Natural gas contracts

Balance Sheet  Regulatory liabilities (long-term)

0.1



0.1



Natural gas contracts

Income Statement  Cost of fuel, natural gas, and purchased power

0.1

(0.1

)

0.2



FTRs

Balance Sheet  Regulatory assets (current)



0.2

(0.6

)

(0.5

)

FTRs

Balance Sheet  Regulatory liabilities (current)



(0.5

)

0.3

(0.4

)

Petroleum product contracts

Balance Sheet  Regulatory assets (current)

0.2



0.1

(0.1

)

Petroleum product contracts

Balance Sheet  Regulatory liabilities (current)

0.1

(0.2

)

0.1



Petroleum product contracts

Income Statement  Operating and maintenance expense



(0.1

)





Coal contract

Balance Sheet  Regulatory assets (current)

0.7

1.1

(2.5

)

0.9

Coal contract

Balance Sheet  Regulatory assets (long-term)

(0.1

)

2.4

0.1

(0.6

)

Coal contract

Balance Sheet  Regulatory liabilities (long-term)



0.5



(3.2

)

We had the following notional volumes of outstanding derivative contracts:

In September 2012, we entered into an agreement to acquire all of the equity interests in Fox Energy Company LLC. The purchase includes the Fox Energy Center, a 593-megawatt combined-cycle electric generating facility in Wisconsin, along with associated contracts. We currently supply natural gas for the facility and purchase 500 megawatts of capacity and the associated energy output under a tolling arrangement.

We will pay $390.0 million to purchase Fox Energy Company LLC, subject to post-closing adjustments, primarily related to working capital. In addition, we will pay $50.0 million to terminate the existing tolling arrangement immediately prior to the acquisition of the facility. The purchase will be financed initially with a combination of short-term debt, cash flow from operations, and an infusion of equity from our parent company. The short-term debt will be replaced later in 2013 with long-term financing.

Fox Energy Center is a dual-fuel facility, equipped to use fuel oil but expected to run primarily on natural gas. This plant will give us a more balanced mix of electric generation, including coal, natural gas, hydroelectric, wind, and other renewable sources.

The transaction is subject to state regulatory approvals, including cost recovery, FERC approvals, and the expiration or termination of the applicable waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976. The transaction is expected to close on or around April 1, 2013.

NOTE 5SHORT-TERM DEBT AND LINES OF CREDIT

Our short-term borrowings were as follows:

(Millions, except percentages)

September 30, 2012

December 31, 2011

Commercial paper outstanding

$

174.3

$

173.7

Average discount rate on outstanding commercial paper

0.24

%

0.26

%

The commercial paper outstanding at September 30, 2012, had maturity dates ranging from October 1, 2012, through October 24, 2012.

The table below presents our average amount of short-term borrowings outstanding based on daily outstanding balances during the nine months ended September 30:

(Millions)

2012

2011

Average amount of commercial paper outstanding

$

156.3

$

33.1

Average amount of short-term notes payable outstanding



4.8

We manage our liquidity by maintaining adequate external financing commitments. The information in the table below relates to our revolving credit facilities used to support our commercial paper borrowing program, including remaining available capacity under these facilities:

(Millions)

Maturity

September 30, 2012

December 31, 2011

Revolving credit facility (1)

04/23/13

$



$

115.0

Revolving credit facility (2)

06/12/13

115.0



Revolving credit facility

05/17/14

135.0

135.0

Total short-term credit capacity

$

250.0

$

250.0

Less:

Letters of credit issued inside credit facilities

$



$

0.2

Commercial paper outstanding

174.3

173.7

Available capacity under existing agreements

$

75.7

$

76.1

(1) This credit facility was terminated in June 2012.

(2) We requested approval from the PSCW to extend this facility through June 13, 2017.

In connection with the pending purchase of Fox Energy Company LLC, we requested approval from the PSCW to temporarily increase our short-term debt limit. See Note 4, Agreement to Purchase Fox Energy Center, for more information regarding this pending purchase.

See our statements of capitalization for details on our long-term debt.

In December 2012, our 4.875% Senior Notes will mature. As a result, the $150.0 million balance of these notes was included in the current portion of long-term debt on our balance sheets.

In February 2013, our 3.95% Senior Notes will mature. As a result, the $22.0 million balance of these notes was included in the current portion of long-term debt on our September 30, 2012, balance sheet.

NOTE 7INCOME TAXES

We calculate our interim period provision for income taxes based on our projected annual effective tax rate as adjusted for certain discrete items.

The table below shows our effective tax rates:

Three Months Ended September 30

Nine Months Ended September 30

2012

2011

2012

2011

Effective Tax Rate

25.0

%

35.8

%

30.5

%

35.9

%

Our effective tax rate normally differs from the federal statutory rate of 35% due to additional provision for state income tax obligations. Other significant items that had an impact on our effective tax rates are noted below.

Our effective tax rates for the three and nine months ended September 30, 2012, were impacted by a $5.9 million decrease in the provision for income taxes resulting from our 2013 rate case settlement agreement. In the third quarter of 2012, we recorded a regulatory asset after the settlement agreement authorized recovery of deferred income taxes expensed in previous years in connection with the 2010 federal health care reform. See Note 15, Regulatory Environment, for more information. Our effective tax rates were also impacted by the federal income tax benefit of tax credits related to wind production and other miscellaneous tax adjustments.

Our effective tax rates for the three and nine months ended September 30, 2011, were impacted by the federal income tax benefit of tax credits related to wind production.

During the three and nine months ended September 30, 2012, there was not a significant change in our liability for unrecognized tax benefits.

NOTE 8COMMITMENTS AND CONTINGENCIES

Commodity Purchase Obligations and Purchase Order Commitments

We routinely enter into long-term purchase and sale commitments for various quantities and lengths of time. We have obligations to distribute and sell electricity and natural gas to our customers and expect to recover costs related to these obligations in future customer rates.

The purchase obligations described below were as of September 30, 2012.

·

Our electric utility segment had obligations of $999.4 million for either capacity or energy related to purchased power that extend through 2029, obligations of $165.4 million related to coal supply and transportation contracts that extend through 2017, and obligations of $0.9 million for other commodities that extend through 2013.

·

Our natural gas utility segment had obligations of $311.3 million related to natural gas supply and transportation contracts that extend through 2024.

·

We also had commitments of $201.7 million in the form of purchase orders issued to various vendors that relate to normal business operations, including construction projects.

Environmental

Clean Air Act (CAA) New Source Review Issues

Weston and Pulliam Plants:

In November 2009, the EPA issued us a Notice of Violation (NOV) alleging violations of the CAAs New Source Review requirements relating to certain projects completed at the Weston and Pulliam plants from 1994 to 2009.

In May 2010, we received from the Sierra Club a Notice of Intent (NOI) to file a civil lawsuit based on allegations that we violated the CAA at the Weston and Pulliam plants. We entered into a Standstill Agreement with the Sierra Club by which the parties agreed to negotiate as part of the EPA NOV process, rather than litigate. The Standstill Agreement ended on October 6, 2012, but further action by the Sierra Club is unknown at this time.

We believe we have reached a tentative agreement with the EPA on general terms to settle these air permitting violation claims and are negotiating a consent decree based upon those general terms, which are subject to change during the negotiations. Based upon the status of the current negotiations and a review of existing EPA consent decrees, we anticipate that the final consent decree could include the installation of emission control technology, changed operating conditions (including fuels other than coal and retirement of units), limitations on emissions, beneficial supplemental environmental projects, and a civil fine. Once the final terms are agreed to, the U.S. District Court must approve the consent decree after a public comment process.

We cannot predict the final outcome of this matter because a final agreement on the consent decree may not be reached, the final terms of the consent decree may be different than currently anticipated, interveners could convince the court to make changes to the terms of the consent decree during the public comment process, or the court may not approve the final consent decree.

Any costs prudently incurred as a result of actions taken due to the consent decree are expected to be recoverable from customers. We are currently unable to estimate the possible loss or range of loss related to this matter.

Columbia and Edgewater Plants:

In December 2009, the EPA issued an NOV to Wisconsin Power and Light (WP&L), the operator of the Columbia and Edgewater plants, and the other joint owners of these plants (including us). The NOV alleges violations of the CAAs New Source Review requirements related to certain projects completed at those plants.

In September 2010, the Sierra Club filed a lawsuit against WP&L, which included allegations that modifications made at the Columbia plant did not comply with the CAA. The case has been dismissed without prejudice as the parties continue to participate in settlement negotiations.

Also in September 2010, the Sierra Club filed a lawsuit against WP&L, which included allegations that modifications made at the Edgewater plant did not comply with the CAA. The case was stayed until July 15, 2012, and a request was made by WP&L to further extend the stay and all deadlines. An update was filed with the court on August 31, 2012, regarding the settlement negotiations with the Sierra Club, the EPA, and the joint owners of the Edgewater plant.

WP&L, Madison Gas and Electric, and we (Joint Owners), along with the EPA and the Sierra Club (collectively, the Parties) are exploring settlement options. The Joint Owners believe that the Parties have reached a tentative agreement on general terms to settle these air permitting violation claims and are negotiating a consent decree based upon those general terms, which are subject to change during the negotiations. Based upon the status of the current negotiations and a review of existing EPA consent decrees, we anticipate that the final consent decree could include the installation of emission control technology, changed operating conditions (including fuels other than coal and retirement of units), limitations on emissions, beneficial supplemental environmental projects, and a civil fine. Once the Parties agree to the final terms, the U.S. District Court must approve the consent decree after a public comment process.

We cannot predict the final outcome of this matter because the Parties may be unable to reach a final agreement on the consent decree, the final terms of the consent decree may be different than currently anticipated, interveners could convince the court to make changes to the terms of the consent decree during the public comment process, or the court may not approve the final consent decree.

Any costs prudently incurred as a result of actions taken due to the consent decree are expected to be recoverable from customers. We are currently unable to estimate the possible loss or range of loss related to this matter.

Weston Air Permits

Weston 4 Construction Permit:

From 2004 to 2009, the Sierra Club filed various petitions objecting to the construction permit issued for the Weston 4 plant. In June 2010, the Wisconsin Court of Appeals affirmed the Weston 4 construction permit, but directed the WDNR to reopen the permit to set specific visible emissions limits. In July 2010, we, the WDNR, and the Sierra Club filed Petitions for Review with the Wisconsin Supreme Court. In March 2011, the Wisconsin Supreme Court denied all Petitions for Review. Other than the specific visible emissions limits issue, all other challenges to the construction permit are now resolved. We are working with the WDNR and the Sierra Club to resolve this issue. We do not expect this matter to have a material impact on our financial statements.

In November 2010, the WDNR provided a draft revised permit. We objected to proposed changes in mercury limits and requirements on the boilers as beyond the authority of the WDNR. We continue to meet with the WDNR to resolve these issues. In September 2011, the WDNR issued an updated draft revised permit and a request for public comments. Due to the significance of the changes to the draft permit, the WDNR intends to re-issue the draft permit for additional comments. On July 24, 2012, Clean Wisconsin filed suit against the WDNR alleging failure to issue or delay in issuing the Weston 4 Title V permit. We are not a party to this litigation, but we filed a request for intervention to protect our interests. Motions regarding intervention and dismissal have also been filed by us and the WDNR. We do not expect this matter to have a material impact on our financial statements.

WDNR Issued NOVs:

Since 2008, we received four NOVs from the WDNR alleging various violations of the different air permits for the entire Weston plant, Weston 1, Weston 2, and Weston 4, as well as one NOV for a clerical error involving pages missing from a quarterly report for Weston. Corrective actions have been taken for the events in the five NOVs. In December 2011, the WDNR dismissed two of the NOVs and referred the other three NOVs to the state Justice Department for enforcement. We and the Justice Department have begun discussing the pending NOVs and their resolution. We do not expect this matter to have a material impact on our financial statements.

Pulliam Title V Air Permit

The WDNR issued the renewal of the permit for the Pulliam plant in April 2009. In June 2010, the EPA issued an order directing the WDNR to respond to comments raised by the Sierra Club in its June 2009 Petition requesting the EPA to object to the permit.

We also challenged the permit in a contested case proceeding and Petition for Judicial Review. The Petition was dismissed in an order remanding the matter to the WDNR. In February 2011, the WDNR granted a contested case proceeding before an Administrative Law Judge on the issues we raised, which included seeking averaging times in the emission limits in the permit. We participated in the contested case proceeding in October 2011. In December 2011, the Administrative Law Judge did not require the WDNR to insert averaging times, for which we had argued. We have decided not to appeal.

In October 2010, we received from the Sierra Club a copy of an NOI to file a civil lawsuit against the EPA based on what the Sierra Club alleged to be an unreasonable delay in responding to the June 2010 order. We received notification that the Sierra Club filed suit against the EPA in April 2011. We are not a party to this litigation, but intervened to protect our interests. In February 2012, the WDNR sent a proposed permit and response to the EPA for a 45-day review, which allowed the parties to enter into a settlement agreement that has been entered by the court. On May 9, 2012, the Sierra Club filed another Petition requesting the EPA to again object to the proposed permit and response. The Sierra Club recently filed a request for a contested case proceeding regarding the permit, which we plan to oppose.

We are reviewing all of these matters, but we do not expect them to have a material impact on our financial statements.

Columbia Title V Air Permit

In October 2009, the EPA issued an order objecting to the permit renewal issued by the WDNR for the Columbia plant. The order determined that the WDNR did not adequately analyze whether a project in 2006 constituted a major modification that required a permit. The EPAs order directed the WDNR to resolve the objections within 90 days and terminate, modify, or revoke and reissue the permit accordingly.

In July 2010, we, along with our co-owners, received from the Sierra Club a copy of an NOI to file a civil lawsuit against the EPA. The Sierra Club alleges that the EPA should assert jurisdiction over the permit because the WDNR failed to respond to the EPAs objection within 90 days.

In September 2010, the WDNR issued a draft construction permit and a draft revised Title V permit in response to the EPAs order. In November 2010, the EPA notified the WDNR that the EPA does not believe the WDNRs proposal is responsive to the order. In January 2011, the WDNR issued a letter stating that upon review of the submitted public comments, the WDNR has determined not to issue the draft permits that were proposed to respond to the EPAs order. In February 2011, the Sierra Club filed for a declaratory action, claiming that the EPA had to assert jurisdiction over the permits. In May 2011, the WDNR issued a second draft Title V permit in response to the EPAs order.

In June 2012, WP&L received notice from the EPA of the EPAs proposal for WP&L to apply for a federally-issued Title V permit since the WDNR has not addressed the EPAs objections to the Title V permit issues for the Columbia plant. The notice gave WP&L 90 days to comment on the EPAs proposal, which was later extended by the EPA to December 15, 2012. If the EPA decides to require the submittal of an operation permit, it would be due within six months of the EPAs notice to WP&L. WP&L believes the previously issued Title V permit for the Columbia plant is still valid. We do not expect this matter to have a material impact on our financial statements.

The State of Wisconsins mercury rule, Chapter NR 446, requires a 40% reduction from the 2002 through 2004 baseline mercury emissions in Phase I, beginning January 1, 2010, through the end of 2014. In Phase II, which begins in 2015, electric generating units above 150 megawatts will be required to reduce mercury emissions by 90% from the 2002 through 2004 baseline. Reductions can be phased in and the 90% target delayed until 2021 if additional sulfur dioxide and nitrogen oxide reductions are implemented. By 2015, electric generating units above 25 megawatts but less than 150 megawatts must reduce their mercury emissions to a level defined by the Best Available Control Technology rule. As of September 30, 2012, we estimate capital costs of approximately $2 million, which includes estimates for both wholly owned and jointly owned plants, to achieve the required Phase I and Phase II reductions. The capital costs are expected to be recovered in future rates.

In December 2011, the EPA issued the final Utility Mercury and Air Toxics rule that will regulate emissions of mercury and other hazardous air pollutants beginning in 2015. We are currently evaluating options for achieving the emission limits specified in this rule, but we do not anticipate the cost of compliance to be significant. We expect to recover future compliance costs in future rates.

Sulfur Dioxide and Nitrogen Oxide:

The EPA issued the Clean Air Interstate Rule (CAIR) in 2005 in order to reduce sulfur dioxide and nitrogen oxide emissions from utility boilers located in 29 states, including Wisconsin and Michigan. In July 2008, the United States Court of Appeals for the District of Columbia Circuit (D.C. Circuit) issued a decision vacating CAIR. In response to requests by numerous parties, including the EPA, the D.C. Circuit reinstated CAIR in December 2008, but directed the EPA to address the deficiencies noted in its previous ruling to vacate CAIR. In July 2011, the EPA issued a final CAIR replacement rule known as the Cross State Air Pollution Rule (CSAPR), which numerous parties, including us, challenged in the D.C. Circuit. The new rule was to become effective January 1, 2012; however, on December 30, 2011, the D.C. Circuit issued a decision that stayed the rule pending resolution of the challenges and directed the EPA to implement CAIR during the stay period. On August 21, 2012, the D.C. Circuit issued their ruling vacating and remanding CSAPR and simultaneously reinstating CAIR pending the issuance of a replacement rule by the EPA. On October 5, 2012, the EPA and several other parties filed petitions for rehearing of the D.C. Circuits decision. Responses to those petitions are due November 16, 2012.

Under CAIR, units affected by the Best Available Retrofit Technology (BART) rule were considered in compliance with BART for sulfur dioxide and nitrogen oxide emissions if they were in compliance with CAIR. This determination was updated when CSAPR was issued (CSAPR satisfied BART) and the EPA has not revised it to reflect the reinstatement of CAIR. Although particulate emissions also contribute to visibility impairment, the WDNRs modeling has shown the impairment to be so insignificant that additional capital expenditures on controls are not warranted.

Due to the uncertainty surrounding this rulemaking, we are currently unable to predict whether this will cause us to purchase additional emission allowances, idle or abandon certain units, or change how certain units are operated. We expect to recover any future compliance costs in future rates.

Manufactured Gas Plant Remediation

We operated facilities in the past at multiple sites for the purpose of manufacturing and storing manufactured gas. In connection with these activities, waste materials were produced that may have resulted in soil and groundwater contamination at these sites. Under certain laws and regulations relating to the protection of the environment, we are required to undertake remedial action with respect to some of these materials. We are coordinating the investigation and cleanup of the sites subject to EPA jurisdiction under what is called a multi-site program. This program involves prioritizing the work to be done at the sites, preparation and approval of documents common to all of the sites, and use of a consistent approach in selecting remedies.

We are responsible for the environmental remediation of ten sites, of which seven have been transferred to the EPA Superfund Alternative Sites Program. Under the EPAs program, the remedy decisions at these sites will be made using risk-based criteria typically used at Superfund sites. As of September 30, 2012, we estimated and accrued for $69.8 million of future undiscounted investigation and cleanup costs for all sites. We may adjust these estimates in the future due to remedial technology, regulatory requirements, remedy determinations, and any claims of natural resource damages. As of September 30, 2012, we recorded a regulatory asset of $79.4 million, which is net of insurance recoveries received of $22.3 million, related to the expected recovery of both cash expenditures and estimated future expenditures through rates. Under current PSCW policies, we may not recover carrying costs associated with the cleanup expenditures.

Management believes that any costs incurred for environmental activities relating to former manufactured gas plant operations that are not recoverable through contributions from other entities or from insurance carriers have been prudently incurred and are, therefore, recoverable through rates. Accordingly, we do not expect these costs to have a material impact on our financial statements. However, any changes in the approved rate mechanisms for recovery of these costs, or any adverse conclusions by the various regulatory commissions with respect to the prudence of costs actually incurred, could materially affect rate recovery of such costs.

Transition obligations, prior service costs (credits), and net actuarial losses that have not yet been recognized as a component of net periodic benefit cost are recorded as net regulatory assets.

We make contributions to our plans in accordance with legal and tax requirements. These contributions do not necessarily occur evenly throughout the year. We contributed $109.4 million to our pension plans and contributions to our other postretirement benefit plans were not significant, during the nine months ended September 30, 2012. We expect to contribute an additional $1.0 million to our pension plans and $12.3 million to our other postretirement benefit plans during the remainder of 2012, dependent upon various factors affecting us, including our liquidity position and tax law changes.

During 2012, $35.3 million of the pension obligation related to the unfunded nonqualified retirement plan was transferred to related parties. Therefore, our balance sheet at September 30, 2012 only reflects the pension liability associated with our past and current employees.

NOTE 10STOCK-BASED COMPENSATION

Our employees may be granted awards under Integrys Energy Groups stock-based compensation plans. Compensation cost associated with these awards is allocated to us based on the percentages used for allocation of the award recipients labor costs.

The following table reflects the stock-based compensation expense and the related deferred tax benefit recognized in income for the three and nine months ended September 30:

Three Months Ended September 30

Nine Months Ended September 30

(Millions)

2012

2011

2012

2011

Stock options

$

0.2

$

0.2

$

0.4

$

0.5

Performance stock rights

0.1



1.8

0.4

Restricted shares and restricted share units

0.8

0.7

2.7

2.6

Total stock-based compensation expense

$

1.1

$

0.9

$

4.9

$

3.5

Deferred income tax benefit

$

0.4

$

0.4

$

2.0

$

1.4

No stock-based compensation cost was capitalized during the three and nine months ended September 30, 2012, and 2011.

Stock Options

The fair value of stock option awards granted was estimated using a binomial lattice model. The expected term of option awards is calculated based on historical exercise behavior and represents the period of time that options are expected to be outstanding. The risk-free interest rate is based on the United States Treasury yield curve. The expected dividend yield incorporates the current and historical dividend rate of Integrys Energy Group. The expected stock price volatility was estimated using its 10-year historical volatility.

The following table shows the weighted-average fair value per stock option granted during the nine months ended September 30, 2012, along with the assumptions incorporated into the valuation model:

February 2012 Grant

Weighted-average fair value per option

$6.30

Expected term

5 years

Risk-free interest rate

0.17% - 2.18%

Expected dividend yield

5.28%

Expected volatility

25%

A summary of stock option activity for the nine months ended September 30, 2012, and information related to outstanding and exercisable stock options at September 30, 2012, is presented below:

Stock Options

Weighted-Average Exercise Price Per Share

Weighted-Average Remaining Contractual Life (in Years)

Aggregate Intrinsic Value (Millions)

Outstanding at December 31, 2011

134,976

$

48.41

Granted

12,435

53.24

Exercised

(33,089

)

46.64

Transfers

(45,720

)

49.06

Outstanding at September 30, 2012

68,602

49.70

5.7

$

0.2

Exercisable at September 30, 2012

38,390

$

50.66

3.6

$

0.1

The aggregate intrinsic value for outstanding and exercisable options in the above table represents the total pre-tax intrinsic value that would have been received by the option holders had they all exercised their options at September 30, 2012. This is calculated as the difference between Integrys Energy Groups closing stock price on September 30, 2012, and the option exercise price, multiplied by the number of in-the-money stock options. The intrinsic value of options exercised during the nine months ended September 30, 2012, and 2011, was not significant.

As of September 30, 2012, future compensation cost expected to be recognized for unvested and outstanding stock options was not significant.

Performance Stock Rights

The fair values of performance stock rights were estimated using a Monte Carlo valuation model. The risk-free interest rate is based on the United States Treasury yield curve. The expected dividend yield incorporates the current and historical dividend rate of Integrys Energy Group. The expected volatility was estimated using one to three years of historical data. The table below reflects the assumptions used in the valuation of the outstanding grants at September 30:

2012

Risk-free interest rate

0.32% - 1.27%

Expected dividend yield

5.28% - 5.34%

Expected volatility

21%  36%

A summary of the activity for the nine months ended September 30, 2012, related to performance stock rights accounted for as equity awards is presented below:

Performance Stock Rights

Weighted-AverageFair Value(2)

Outstanding at December 31, 2011

4,629

$

46.16

Granted

840

52.70

Award modifications(1)

2,569

79.62

Distributed

(2,347

)

42.86

Adjustment for final payout

(825

)

42.86

Transfers

42

50.21

Outstanding at September 30, 2012

4,908

$

66.95

(1)Six months prior to the end of the performance period, employees can no longer change their election to defer the value of their performance stock rights into the deferred compensation plan. As a result, any awards not elected for deferral at this point in the performance period will be settled in Integrys Energy Groups common stock. This changes the classification of these awards from a liability award to an equity award. The change in classification is accounted for as an award modification.

(2)Reflects the weighted-average fair value used to measure equity awards. Equity awards are measured using the grant date fair value or the fair value on the modification date.

The weighted-average grant date fair value of performance stock rights awarded during the nine months ended September 30, 2012, and 2011, was $52.70 and $49.21, per performance stock right, respectively.

A summary of the activity for the nine months ended September 30, 2012, related to performance stock rights accounted for as liability awards is presented below:

Performance Stock Rights

Outstanding at December 31, 2011

5,815

Granted

3,354

Award modifications*

(2,569

)

Transfers

174

Outstanding at September 30, 2012

6,774

*Six months prior to the end of the performance period, employees can no longer change their election to defer the value of their performance stock rights into the deferred compensation plan. As a result, any awards not elected for deferral at this point in the performance period will be settled in Integrys Energy Groups common stock. This changes the classification of these awards from a liability award to an equity award. The change in classification is accounted for as an award modification.

The weighted-average fair value of all outstanding performance stock rights accounted for as liability awards as of September 30, 2012, was $49.99 per performance stock right.

As of September 30, 2012, future compensation cost expected to be recognized for unvested and outstanding performance stock rights (equity and liability awards) was not significant.

The total intrinsic value of performance stock rights distributed during the nine months ended September 30, 2012, and 2011, was not significant.

Restricted Shares and Restricted Share Units

During the second quarter of 2011, the last of the outstanding restricted shares vested. Only restricted share units remain outstanding at September 30, 2012.

A summary of the activity related to all restricted share unit awards (equity and liability awards) for the nine months ended September 30, 2012, is presented below:

Restricted ShareUnit Awards

Weighted-Average Grant Date Fair Value

Outstanding at December 31, 2011

67,227

$

45.18

Granted

23,880

53.24

Dividend equivalents

2,461

48.20

Vested and released

(27,247

)

45.12

Transfers

(113

)

45.20

Forfeited

(256

)

53.24

Outstanding at September 30, 2012

65,952

48.27

As of September 30, 2012, $1.3 million of compensation cost related to these awards was expected to be recognized over a weighted-average period of 2.2 years.

The total intrinsic value of restricted share and restricted share unit awards vested and released during the nine months ended September 30, 2012, and 2011, was $1.5 million and $1.0 million, respectively. The actual tax benefit realized for the tax deductions from the vesting and releasing of restricted shares and restricted share units during the nine months ended September 30, 2012, and 2011, was not significant.

The weighted-average grant date fair value of restricted share units awarded during the nine months ended September 30, 2012, and 2011, was $53.24 and $49.40 per share, respectively.

NOTE 11COMMON EQUITY

Various laws, regulations, and financial covenants impose restrictions on our ability to pay dividends to the sole holder of our common stock, Integrys Energy Group.

The PSCW allows us to pay dividends on our common stock of no more than 103% of the previous years common stock dividend. We may return capital to Integrys Energy Group if our average financial common equity ratio is at least 50.24% on a calendar year basis. We must obtain PSCW approval if a return of capital would cause our average financial common equity ratio to fall below this level. Integrys Energy Groups right to receive dividends on our common stock is also subject to the prior rights of our preferred

shareholders and to provisions in our restated articles of incorporation, which limit the amount of common stock dividends that we may pay if our common stock and common stock surplus accounts constitute less than 25% of our total capitalization.

Our short-term debt obligations contain financial and other covenants, including but not limited to, a requirement to maintain a debt to total capitalization ratio not to exceed 65%. Failure to comply with these covenants could result in an event of default, which could result in the acceleration of outstanding debt obligations.

As of September 30, 2012, total restricted net assets were $1,100.4 million. Our equity in undistributed earnings of 50% or less owned investees accounted for by the equity method was $27.0 million at September 30, 2012.

Except for the restrictions described above and subject to applicable law, we do not have any other significant dividend restrictions.

Integrys Energy Group may provide equity contributions to us or request a return of capital from us in order to maintain utility common equity levels consistent with those allowed by the PSCW. Wisconsin law prohibits us from making loans to or guaranteeing obligations of Integrys Energy Group or its other subsidiaries. During the nine months ended September 30, 2012, we received $40.0 million of equity contributions from Integrys Energy Group, paid common stock dividends of $79.1 million to Integrys Energy Group, and returned $50.0 million of capital to Integrys Energy Group.

NOTE 12VARIABLE INTEREST ENTITIES

We have a variable interest in an entity through a power purchase agreement relating to the cost of fuel. This agreement contains a tolling arrangement in which we supply the scheduled fuel and purchase capacity and energy from the facility. In connection with the pending purchase of Fox Energy Company LLC, we will pay $50.0 million to terminate this tolling arrangement. See Note 4, Agreement to Purchase Fox Energy Center, for more information regarding this pending purchase. As of September 30, 2012, and December 31, 2011, we had 500 megawatts of capacity available under this agreement.

We evaluated this variable interest entity for possible consolidation. We considered which interest holder has the power to direct the activities that most significantly impact the economics of the variable interest entity; this interest holder is considered the primary beneficiary of the entity and is required to consolidate the entity. For a variety of reasons, including qualitative factors such as the length of the remaining term of the contracts compared with the remaining lives of the plants and the fact that we do not have the power to direct the operations and maintenance of the facilities, we determined we are not the primary beneficiary of this variable interest entity.

At September 30, 2012, and December 31, 2011, the assets and liabilities on the balance sheets that related to our involvement with this variable interest entity pertained to working capital accounts and represented the amounts we owed for current deliveries of power. We have not guaranteed any debt or provided any equity support, liquidity arrangements, performance guarantees, or other commitments associated with this contract. There is not a significant potential exposure to loss as a result of our involvement with the variable interest entity.

NOTE 13FAIR VALUE

Fair Value Measurements

The following tables show assets and liabilities that were accounted for at fair value on a recurring basis, categorized by level within the fair value hierarchy:

We determine fair value using a market-based approach that uses observable market inputs where available, and internally developed inputs where observable market data is not readily available. For the unobservable inputs, consideration is given to the assumptions that market participants would use in valuing the asset or liability. These factors include not only the credit standing of the counterparties involved, but also the impact of our nonperformance risk on our liabilities.

The risk management assets and liabilities listed in the tables above include NYMEX futures and options, as well as financial contracts used to manage transmission congestion costs in the MISO market. NYMEX contracts are valued using the NYMEX end-of-day settlement price, which is a Level 1 input. The valuation for FTRs is derived from historical data from MISO, which is considered a Level 3 input. The valuation for the physical coal contract is categorized in Level 3, as significant assumptions were made to extrapolate prices from the last quoted period through the end of the transaction term. For more information on our derivative instruments, see Note 3, Risk Management Activities. There were no transfers between the levels of the fair value hierarchy during the three and nine months ended September 30, 2012, and 2011.

We have established a risk oversight committee whose primary responsibility includes directly or indirectly ensuring that all valuation methods are applied in accordance with predefined policies. The development and maintenance of our forward price curves has been assigned to our risk management department, which is part of the corporate treasury function. This group is separate and distinct from the trading function. To validate the reasonableness of our fair value inputs, our risk management department compares changes in valuation and researches any significant differences in order to determine the underlying cause. Corrections to the fair value inputs are made if necessary.

The significant unobservable inputs used in the valuation that resulted in categorization within Level 3 were as follows at September 30, 2012. The amounts and percentages listed in the table below represent the range of unobservable inputs that individually had a significant impact on the fair value determination and caused a derivative to be classified as Level 3.

Fair Value (Millions)

Assets

Liabilities

Valuation Technique

Unobservable Input

Average or Range

FTRs

$

1.9

$

0.2

Market-based

Forward market prices ($/megawatt-month) (1)

96.63

Coal contract



$

9.3

Market-based

Forward market prices ($/ton) (2)

14.75  16.20

(1)Represents forward market prices developed using historical cleared pricing data from MISO used in the valuation of FTRs.

(2)Represents third-party forward market pricing used in the valuation of our coal contract.

Significant changes in historical settlement prices and forward coal prices would result in a directionally similar significant change in fair value.

The following table sets forth a reconciliation of changes in the fair value of items categorized as Level 3 measurements:

Three Months Ended September 30, 2012

Nine Months Ended September 30, 2012

(Millions)

FTRs

Coal Contract

Total

FTRs

Coal Contract

Total

Balance at the beginning of period

$

2.5

$

(9.8

)

$

(7.3

)

$

1.2

$

(6.9

)

$

(5.7

)

Net realized (losses) gains included in earnings

(0.6

)



(0.6

)

1.4



1.4

Net unrealized gains (losses) recorded as regulatory assets or liabilities

Net unrealized (losses) gains recorded as regulatory assets or liabilities

(0.3

)

4.2

3.9

(0.9

)

(1.7

)

(2.6

)

Purchases







2.8



2.8

Sales

(0.1

)



(0.1

)

(0.2

)



(0.2

)

Settlements

(1.0

)

(0.4

)

(1.4

)

(0.4

)

(1.3

)

(1.7

)

Balance at the end of period

$

2.2

$

(0.5

)

$

1.7

$

2.2

$

(0.5

)

$

1.7

Unrealized gains and losses on FTRs and the coal contract are deferred as regulatory assets or liabilities. Therefore, these fair value measurements have no impact on earnings. Realized gains and losses on FTRs, as well as the related transmission congestion costs, are recorded in cost of fuel, natural gas, and purchased power on the statements of income.

Fair Value of Financial Instruments

The following table shows the financial instruments included on our balance sheets that are not recorded at fair value.

September 30, 2012

December 31, 2011

(Millions)

Carrying Amount

Fair Value

Carrying Amount

Fair Value

Long-term debt

$

721.4

$

820.6

$

721.3

$

816.7

Long-term debt to parent

7.4

8.5

7.9

9.2

Preferred stock

51.2

52.7

51.2

51.9

The fair values of long-term debt are estimated based on the quoted market price for the same or similar issues, or on the current rates offered to us for debt of the same remaining maturity. The fair values of preferred stock are estimated based on quoted market prices, when available, or by using a perpetual dividend discount model. The fair values of long-term debt instruments and preferred stock are categorized within Level 2 of the fair value hierarchy.

Due to the short-term nature of cash and cash equivalents, accounts receivable, accounts payable, notes payable, and outstanding commercial paper, the carrying amount for each such item approximates fair value.